Deepwater exploration drives advances in subsurface hanger technology, as operators seek to lighten the load on production floaters.

Subsurface tubing hangers were developed during the 1960s to support the increase in offshore oil and gas drilling activity and the resulting new safety and environmental regulations. The new regulations required use of surface-controlled, subsurface safety systems, but unfortunately, during that period, they did not provide the reliability they do today. The early subsurface tubing hangers had been designed primarily to hang off the production tubing string while the upper tubing string was recovered, and also to prevent the tubing seals from pulling out of the production packer should a catastrophic event occur. The upper tubing string included the tubing-retrievable safety valve (TRSV) or safety valve landing nipple (SVLN). Subsurface tubing hangers were also called mudline tubing hangers (MLTH), packoff tubing hangers (POTH), or packoff mudline hangers (POMLH). During this time frame, the primary purpose of the MLTH systems was to allow the subsurface safety system to be repaired using a crane rather than a workover rig.

In addition to the capability to repair the subsurface safety system, a shear joint above the safety valve was included in some completions so that if the platform sustained damage from shipping traffic or weather, loss of the wellhead would result in the tubing parting above the closed safety valve.
Technology eventually improved the reliability of the subsurface safety valve systems to the point where the need for the subsurface hangers declined. In addition, risk of catastrophic damage due to ship collisions and weather-related events proved to be negligible in part due to advances in platform design and also as a result of other safeguards. Therefore, use of these subsurface tubing hanger systems virtually vanished by the early 1980s.

In July 1988, a catastrophic event that occurred in the North Sea revealed the need for annular safety valve (ASV) systems in some instances. This need caused the industry to revisit the potentials offered by subsurface tubing hangers with the addition of packer element systems and surface-controlled safety valve (SCSV) mechanisms. The primary focus of this equipment was the SCSV mechanism rather than the subsurface tubing hanger design itself. The large tubing sizes and long tubing lengths produced high axial and pressure-induced loads, requiring innovative solutions to protect unsupported casing at the depths that the ASV packers were to be set.

Today, subsurface tubing hanger technology has resurfaced into a broader scope of usage, and configurations have evolved into devices made up in the production tubing string of oil- and gas-well completions that have external slip mechanisms similar to those used with packers designed to grip the casing wall. Some of these hangers include packer element systems designed to hold pressure differentials that can change during the well's lifetime. Current applications are discussed below.

New subsurface tubing hanger applications in today's oilfield

As deepwater exploitation of oil and gas increased, so did operational costs, and operators were compelled to consider every opportunity to reduce risk and improve operability. Two primary areas of interest were weight management and flow assurance.

Weight management efforts strive to reduce the size of floating platforms such as tension leg platforms (TLP) and spars, resulting in a decrease in their capability to support the weight of risers and the production tubing. Risers on spars are self-supported with the use of buoyancy cans, while TLP wells are supported by tensioners tied back to the deck. Risk analysis of the well system must take into account the potential loss of some or all of this support. The well system must be capable of safely withstanding the potential outcomes should an unplanned event occur.

One effective method for reducing the weight that the TLP or Spar must support is to transfer part of the weight of the production tubing to a subsurface tubing hanger. The capability to relieve the floating platform of this weight can result in significant savings in the cost of the platform.

The use of a single riser instead of the usual two is also attractive from a weight management standpoint. However, the Minerals Management Service (MMS) requires two barriers for wells completed in the outer continental shelf (OCS). A POTH could serve as a second barrier and allow the use of the single riser in this regard. This technology is easier to implement than the installation of a tubing hanger in the subsea wellhead.

The mudline hanger can also increase completion reliability by stabilizing the seals in the production or gravel-pack packer below. Seal movement is generally managed by attempting to maintain weight on the packer during most anticipated production scenarios. The mudline hanger effectively isolates the upper riser section of the completion where the major thermal cycles (and length changes) will occur. For wells that do not require a mudline hanger, a specifically designed packer installed with the tubing string can accomplish this goal.

Aside from weight management concerns, deepwater completions experience serious flow assurance issues due to thermal challenges. The cold temperatures at the seabed may cause the produced fluids to form hydrates and plug the tubing inside diameter (ID). Cooler fluids can also result in reduced production rates because of increased viscosity and deposition of paraffin. Numerous methods are employed to insulate the production tubing from the seabed to the platform, including vacuum-insulated tubing, nitrogen in the riser, and thermal gel in the riser. If the well requires gas lift, injecting the gas down the riser casing annulus might not be desirable since this can result in significant heat loss from the produced fluids.

A POTH or packoff MLTH can, therefore, become an essential part of a deepwater completion from a floating platform with dry wellheads. With the annulus packed off below the mudline, thermal gel or nitrogen can be placed in the riser annulus to control heat loss. In addition, a side string may be run parallel to the production string for gas-lift operations below the POTH (Figure 1).

Unfortunately, attempts to use old technology in deepwater applications reveal design deficiencies in the following areas of concern:

• Wide thermal cycles
• High potential compressive loads
• Probability of uncemented casing at setting depth
• Requirement of multiple control lines and instrument cable bypasses
• Length
• High reliability
• Simple and redundant release methods

The packoff MLTH can be exposed to temperatures below 40?F (4?C), and during production, can heat up to temperatures of 200?F (93?C) or more. During static conditions, the MLTH will return to the lower temperature. This is detrimental to conventional packer element systems and requires unique designs to retain pressure integrity.

Many deepwater completions feature large tubing strings both in outside diameter (OD) and length. As the well is produced, the upper tubing string heats up and elongates, creating increased compressive loads on the mudline hanger. The design should be adequate to carry these compressive loads under cyclic conditions from production to shut-in periods without detrimental effects. The tubing landing scheme should be to keep the tubing nominally in tension at the hanger to improve connection fatigue performance and minimize the potential for riser wear.

It is common practice not to cement the production casing to the mudline. This results in the packoff MLTH being set inside unsupported casing. Stresses from the packer slips and element systems may damage unsupported casing. The MLTH slip and element system must accommodate these conditions in order to avoid damage to the casing that could result in catastrophic failure of the completion. In addition, annular pressure buildup issues caused by production heating of annular fluids can exacerbate these conditions (Figure 2).

A multitude of bypass ports is typically required in deepwater completions to accommodate hydraulic lines to operate subsurface safety valves, injection lines for chemical injection, and instrument cables for downhole pressure and temperature gauges. The capability to accommodate these lines in addition to the production conduit and secondary conduit for annulus access requires a unique design to avoid leak paths and operational difficulties.

Long assemblies are difficult to transport and handle during wellsite activities. Therefore, the packoff MLTH should be relatively short in length to allow handling subs to be preassembled and tested in the workshop and to allow for efficient handling offshore. Long assemblies are awkward to handle and risk damage, pose safety concerns, and usually result in additional rig time needed to place the assembly in the tubing string.

Since the packoff MLTH essentially takes the place of a subsea wellhead, its reliability is equally as critical. This is especially true if a single riser is used from the seabed to the platform, and the MLTH is considered a second barrier. Elimination of leak paths and design simplicity are keys for reliability.
Qualification tests meeting the requirements of a modified ISO 14310 V0 level should be the minimum acceptable requirement for this type of equipment. The modified version of the test is to set the MLTH at a temperature of less than 40?F (4?C), and then, to heat it to the maximum temperature rating followed by a cool down test, whereas ISO 14310 requires the packer to be set at the maximum temperature and cooled down. The modified procedure is more stringent and more closely represents actual operating conditions.
In the event the well is to be worked over, the release method of the packoff MLTH should be simple. Straight shear is typically unacceptable due to the risk of premature release during production and injection operations. Typical methods include cutting the mandrel, hydraulic release using a dedicated plug run on slickline, and mechanical release via the secondary string. Other methods that use techniques referred to as punch-to-release have been used successfully but require additional slickline trips to install and retrieve tubing plugs. Regardless of the methods required, they should be relatively simple, and it is best to offer multiple release methods in a single design.

It is interesting to note how a previously abandoned but well proven concept has been adapted to fulfill a new concept of functionality.

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